Section 95103 - Greenhouse Gas Reporting RequirementsThe facilities, suppliers, and entities specified in section 95101 must monitor emissions and submit emissions data reports to the Air Resources Board following the requirements specified in 40 CFR § 98.3 and § 98.4, except as otherwise provided in this part.
(a)Abbreviated Reporting for Facilities with Emissions Below 25,000 Metric Tons of CO2e. A facility operator may submit an abbreviated emissions data report under this article if all of the following conditions have been met: the facility operator does not have a compliance obligation under the cap-and-trade regulation during any year of the current compliance period; the operator is not subject to the reporting requirements of 40 CFR Part 98 specified in this article; and the facility total stationary combustion, process, fugitives and venting emissions are below 25,000 metric tons of CO2e in the data year. This provision does not apply to suppliers or electric power entities. Abbreviated reports must include the information in paragraphs (1)-(7) below, and comply with the requirements specified in paragraphs (8)-(11) below:(1) Facility name, assigned ARB identification number, physical street address including the city, state and zip code, air basin, air district, county, geographic location, natural gas supplier name, natural gas supplier customer identification number, natural gas supplier service account identification number or other primary account identifier, and annual billed MMBtu (10 therms = 1 MMBtu).(2) Facility GHG stationary combustion emissions for all stationary fuel combustion units and calculated according to any method in 40 CFR § 98.33(a), expressed in metric tons of total CO2, CO2 from biomass-derived fuels, CH4, and N2O. Using any applicable method in 40 CFR § 98.33 or 95153 (l), reporting entities identified under section 95101(e) for petroleum and natural gas systems must also quantify and report emissions of CO2, CO2 from biomass-derived fuels, CH4, and N2O resulting from flaring activities. If a facility includes multiple stationary fuel combustion units that belong to more than one unit type category listed in section 95115(h), the operator may report the multiple units in aggregate but must indicate the percentage of the aggregated fuel consumption attributed to each unit type category. In addition, if a facility includes an electricity generating unit, the facility operator must report the electricity generating unit separate from other stationary fuel combustion sources by following the unit aggregation provisions in sections 95112(b) and 95103(a)(6). The operator has the option of using engineering estimation or any combination of existing meters to meet the requirements of this paragraph.(3) Total facility GHG process emissions aggregated for all process emissions sources and calculated according to the requirements in the following parts, expressed in metric tons of total CO2, CO2 from biomass-derived fuels, CH4, and N2O, as applicable:(A)40 CFR § 98.143 for glass production;(B)40 CFR § 98.163 for hydrogen production;(C)40 CFR § 98.173 for iron and steel production;(D)40 CFR § 98.273 for pulp and paper manufacturing;(E) Subarticle 5 of this article for petroleum and natural gas systems.(4) Identification of the methods chosen for determining emissions.(5) Any facility operating data or process information used for the GHG emission calculations, including fuel use by fuel type, reported in million standard cubic feet for gaseous fuels, gallons for liquid fuels, short tons for solid fuels, and bone-dry short tons for biomass-derived solid fuels. If applicable, include high heat values and carbon content values used to calculate emissions. Missing fuel use or fuel characteristics data must be substituted according to the requirements of 40 CFR § 98.35.(6) For facilities with on-site electricity generation or cogeneration, the applicable information specified in section 95112(a)-(b) of this article. Geothermal facilities must also report the information specified in section 95112(e). Operators of hydrogen fuel cells must report the information specified in section 95112(f).(7) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of 40 CFR § 98.4(e)(1).(8) Abbreviated emissions data reports submitted under this provision must be certified as complete and accurate no later than June 1 of each calendar year.(9) Subsequent revisions according to the requirements of 40 CFR § 98.3(h) must be submitted if an error is discovered after the submission of the emissions data report. If the error correction would cause the emissions total to exceed 25,000 metric tons of CO2e, a report that meets the full requirements of this article must be submitted within ninety days of discovery.(10) For abbreviated reports submitted under this provision, records must be kept according to the requirements of 40 CFR § 98.3(g), except that a written GHG Monitoring Plan is not required.(11) An abbreviated emissions data report is not subject to the third-party verification requirements of this article.(e)Reporting Deadlines. Except as provided in section 95103(a)(7)-(8), each facility operator or supplier must submit an emissions data report no later than April 10 of each calendar year. Each electric power entity must submit an emissions data report no later than June 1 of each calendar year.(f)Verification Requirement and Deadlines. The requirements of this paragraph apply to each reporting entity submitting an emissions data report that indicates emissions equaled or exceeded 25,000 metric tons of CO2e, including CO2 from biomass-derived fuels and geothermal sources, electric power entities that are electricity importers or exporters, facilities with sources as identified in section 95101(b)(3), or each reporting entity that has or has had a compliance obligation under the cap-and-trade regulation in any year of the current compliance period. The requirements of this paragraph apply to reporting entities that have not met the requirements for cessation of verification in section 95101(i). The reporting entity subject to verification must obtain third-party verification services for that report from a verification body that meets the requirements specified in Subarticle 4 of this article. Such services must be completed and separate verification statements for emissions data and for product data, as applicable, must be submitted by the verification body to the Executive Officer by August 10 each year. Each reporting entity must ensure that these verification statements are submitted by this deadline. Contracting with a verification body without providing sufficient time to complete the verification statements by the applicable deadline will not excuse the reporting entity from this responsibility. These requirements are additional to the requirements in 40 CFR § 98.3(f).(g)Non-submitted/Non-verified Emissions Data Reports. When a reporting entity that holds a compliance obligation under the cap-and-trade regulation fails to submit an emissions data report or fails to obtain a positive emissions data verification statement or qualified positive emissions data verification statement by the applicable deadline, the Executive Officer shall develop an assigned emissions level for the reporting entity as set forth in section 95131(c)(5)(A)-(C).(h)Reporting in 2018. All provisions of the regulation are in full effect for 2019 data reporting in 2020 and beyond, except the following: (1) The requirements of 95101(h) and (i) are effective for 2018 data reported in 2019.(2) The method in section 95153(a) for continuous bleed pneumatic devices applies to 2019 data reported in 2020.(3) The provisions of Subarticle 6 of this article become effective for 2021 data submitted in 2022, if U.S. EPA has approved, as memorialized by publication in the Federal Register and Code of Federal Regulations, that provision as part of California's plan for compliance with the Clean Power Plan.(i)Calculation and Reporting of De Minimis Emissions. A facility operator may designate as de minimis a portion of GHG emissions representing no more than 3 percent of a facility's total CO2 equivalent emissions (including emissions from biomass-derived fuels and feedstocks), not to exceed 20,000 metric tons of CO2e. The operator or supplier may estimate de minimis emissions using alternative methods of the operator's choosing, subject to the concurrence of the verification body that the methods used are reasonable, not biased toward significant underestimation or overestimation of emissions, and unlikely to exceed the de minimis limits. The operator must separately identify and include in the emissions data report the emissions from designated de minimis sources. The operator must determine CO2 equivalence according to the global warming potentials as specified in the "global warming potential" definition of this article.(j)Calculating, Reporting, and Verifying Emissions from Biomass-Derived Fuels. The operator or supplier must separately identify and report all biomass-derived fuels as described in section 95852.2(a) of the cap-and-trade regulation. Except for operators that use the methods of 40 CFR § 98.33(a)(2)(iii) or § 98.33(a)(4), the operator or supplier must separately identify, calculate, and report all direct emissions of CO2 resulting from the combustion of biomass-derived fuels as specified in sections 95112 and 95115 for facilities, and sections 95121 and 95122 for suppliers. A biomass-derived fuel not listed in section 95852.2(a) of the cap-and-trade regulation must be identified as non-exempt biomass-derived fuel. For a fuel listed under section 95852.2 of the cap-and-trade regulation, reporting entities must also meet the verification requirements in section 95131(i) of this article and the requirements of section 95852.1.1 of the cap-and-trade regulation, or the fuel must be identified as non-exempt biomass-derived fuel. Carbon dioxide combustion emissions from non-exempt biomass-derived fuel will be identified as non-exempt biomass-derived CO2. The responsibility for obtaining verification of a biomass-derived fuel falls on the entity that is claiming there is not a compliance obligation for the fuel, as indicated in section 95852.2 of the cap-and-trade regulation. (1) When reporting solid waste, the reporting entity must separately report the mass, in short tons, of urban waste, agricultural waste, and municipal solid waste.(2) When reporting the use of forest derived wood and wood waste as identified in section 95852.2(a)(4) of the cap-and-trade regulation and harvested pursuant to any section of the California Forest Practice Rules Title 14, California Code of Regulations, Chapters 4, 4.5 and 10 of the Federal National Environmental Policy Act, the reporting entity must report: the bone-dry mass received; information about the supplier, including the name, physical address, mailing address, contact person with phone number and e-mail address; and the corresponding identification number under which the wood was removed.(3) When reporting biomethane, the operator or supplier who is reporting biomass emissions from biomethane fuel must also report the following information for each contracted delivery: (A) Name and address of the biomethane vendor from which biomethane is purchased;(B) Annual MMBtu delivered by each biomethane vendor. The operator must also report the name, address, and facility type of the facility from which the biomethane is produced. In addition, relevant documentation including invoices, shipping reports, allocation and balancing reports, storage reports, in-kind nomination reports, and contracts must be made available for verifier or ARB review to demonstrate the receipt of eligible biomethane.
(4) Reporting of fuel consumption from non-exempt biomass-derived fuel is subject to the requirements of section 95103(k) and reporting of emissions from non-exempt biomass-derived fuels is subject to the requirements of sections 95110 to 95158.(k)Measurement Accuracy Requirement. The operator or supplier subject to the requirements of 40 CFR § 98.3(i) must meet those requirements for data used for calculating non-covered emissions and non-covered product data, except as otherwise specified in this paragraph. In addition, the following accuracy requirements apply to data used for calculating covered emissions and covered product data. The operator or supplier with covered product data or covered emissions equal to or exceeding 25,000 metric tons of CO2e or a compliance obligation under the cap-and-trade regulation in any year of the current compliance period must meet the requirements of paragraphs (k)(1)-(10) below for calibration and measurement device accuracy. Inventory measurement, stock measurement, or tank drop measurement methods are subject to paragraph (11) below. The requirements of paragraphs (k)(1)-(11) apply to fuel consumption monitoring devices, feedstock consumption monitoring devices, process stream flow monitoring devices, steam flow devices, product data measuring devices, mass and fluid flow meters, weigh scales, conveyer scales, gas chromatographs, mass spectrometers, calorimeters, and devices for determining density, specific gravity, and molecular weight. The provisions of paragraph (k)(1)-(11) do not apply to: stationary fuel combustion units that use the methods in 40 CFR § 98.33(a)(4) to calculate CO2 mass emissions; emissions reported as de minimis under section 95103(i); and devices that are solely used to measure parameters used to calculate emissions that are not covered emissions or that are not covered product data. The provisions of paragraphs (k)(1)-(9) and (k)(11) do not apply to stationary fuel combustion units that use the methods in 40 CFR Part 75 Appendix G § 2.3 to calculate CO2 mass emissions, but the provisions in paragraph (k)(10) are applicable to such units.(1) Except as otherwise provided in sections 95103(k)(7) through (9), all flow meter and other measurement devices used to provide data for the GHG emissions calculations or covered product data must be calibrated prior to the year data collection is required to begin using the procedures specified in this section, and subsequently recalibrated according to the frequency specified in paragraph (4). Flow meters and other measurement devices that were calibrated prior to January 1, 2012 using procedures specified in previous versions of the Mandatory Reporting Regulation or methods specified in 40 CFR Part 98 must be subsequently recalibrated according to the frequency specified in paragraph (4). A flow meter device consists of a number of individual components which might include a flow constriction component, mechanical component, and temperature and pressure measurement components. Each meter or measurement device must meet the applicable accuracy specification in section 95103(k)(6), however each individual component of a flow meter device is not required to meet the accuracy specifications. The procedures and methods used to quality-assure the data from each measurement device must be documented in the written monitoring plan required by section 95105(c).(2) All flow meters and other measurement devices that provide data used to calculate GHG emissions or product data must be calibrated according to either the manufacturer's recommended procedures or a method specified in an applicable subpart of 40 CFR Part 98. The calibration method(s) used must be documented in the monitoring plan required under section 95105(c), and are subject to verification under this article and review by ARB to ensure that measurements used to calculate GHG emissions or product data have met the accuracy requirements of this section.(3) For facilities and suppliers that become subject to this article after January 1, 2012, all flow meters and other measurement devices that provide data used to calculate GHG emissions or product data must be installed and calibrated no later than the date on which data collection is required to begin under this article.(4) Except as otherwise provided in sections 95103(k)(7) through (9), subsequent recalibrations of the flow meter and other measurement devices subject to the requirements of this section must be performed no less frequently than at one of the following time intervals, whichever is shortest:(A) The frequency specified in a subpart of 40 CFR Part 98 that is applicable under this article.(B) The frequency recommended by the manufacturer.(C) Once every 36 months.(D) Immediately upon replacement of a previously calibrated meter.(E) Immediately upon replacement or repair of a device that is deemed out of calibration as determined in paragraph (6).(F) If the device manufacturer explicitly states in the product documentation that calibration is required at a period exceeding three years, the operator may follow the procedures in paragraph (9) to obtain Executive Officer approval to relieve the operator from having to comply with provisions (A) and (C) of this subparagraph.(5) All standards used for calibration must be traceable to the National Institute of Standards and Technology or other similar national government body responsible for measurement standards.(6) In addition to the specific calibration requirements specified below, and, if applicable, the field accuracy assessment requirements specified below, all flow meter and other measurement devices covered by this section, regardless of type, must be selected, installed, operated, and maintained in a manner to ensure accuracy within +5 percent.(A) Perform all mass and volume measurement device calibration as specified in the original equipment manufacturer's (OEM) documentation. If OEM documentation is unavailable, calibrate as specified in 40 CFR § 98.3(i)(2)-(3), except that a minimum of three calibration points must be used spanning the normal operating conditions. When using the three calibration points, one point must be at or near the zero point, one point must be at or near the upscale point, and one point at or near the mid-point of the devices operating range. If OEM documentation does not specify a method or is unavailable, and calibration methods specified in 40 CFR § 98.3(i)(2)-(3) are not possible for a particular device, the procedures in section 95109(b) must be followed to obtain approval for an alternative calibration procedure. Additionally: 1. Pressure differential devices must be inspected at a frequency specified in paragraph (k)(4) of this section, unless the device is located at a refinery or hydrogen plant that operates continuously with infrequent outages. In such cases, the owner or operator of the refinery or hydrogen plant must inspect each device at a frequency of at least once every six years. The inspection must be conducted as described in the appropriate part of ISO 5167-2 (2003), or AGA Report No 3 (2003) Part 2, both of which are incorporated by reference, or a method published by an organization listed in 40 CFR § 98.7 applicable to the analysis being conducted. If the device fails any one of the tests then the meter shall be deemed out of calibration. If OEM guidance for a particular pressure differential device recommends against disassembly and inspection of the device, disassembly and inspection requirements in this paragraph do not apply. Documentation of OEM guidance must be made available to verifiers and ARB upon request.a. Records of all tests, including an as-found condition, must be preserved pursuant to section 95105 and made available to verifiers and ARB upon request.b. Where inspection requirements apply, the primary element must also be photographed on both sides prior to any treatment or cleanup of the element to clearly show the condition of the element as it existed in the pipe.2. Devices used to measure total pressure and temperature must be calibrated using methods specified in section 95103(k)(2) and at a frequency specified in section 95103(k)(4).3. If temperature and/or total pressure measurements are not available or are taken at a remote location, the uncertainty caused by this must be factored into the evaluation of the overall measurement accuracy required under section 95103(k)(6).(B) Operators and suppliers may conduct an annual field accuracy assessment of mass and volume measurement devices to test for field accuracy in years between successive calibrations to ensure the device is maintaining measurement accuracy within +5 percent. When performing a field accuracy assessment, the as-found condition must be recorded to ensure the device is measuring with accuracy within +5 percent. Should a device be found to be operating outside the +5 percent accuracy bounds, the device shall be deemed out of calibration. Records of all field accuracy assessments must clearly indicate the assessment procedure and the as-found condition, be preserved pursuant to section 95105, and be made available to verifiers and ARB upon request. Device accuracy may be assessed using one of the following options: 2. OEM calibration guidance or other OEM recommended methods;3. Standard industry practices; or(C) Pursuant to paragraph (k)(10) of this section, in the event of a failed calibration or recalibration, operators or suppliers who choose not to perform the annual field accuracy assessment specified in paragraph (6)(B) of this section for one or more mass or volume measurement devices must demonstrate data accuracy going back multiple years to the most recent successful calibration. Multiple years of data may be deemed invalid if accuracy cannot be demonstrated by other means, including strap-on meters or engineering methods. For operators and suppliers who conduct the annual field accuracy assessment, and a device is found to be out of calibration, accuracy must be demonstrated back to the most recent successful calibration or the most recent successful field accuracy assessment, whichever is most recent.(7) The requirements of section 95103(k) do not apply under the following circumstances: (A) Financial transaction meters are exempted from the calibration requirements of section 95103(k) if the supplier and purchaser do not have any common owners and are not owned by subsidiaries or affiliates of the same company. Financial transaction meters where the supplier and the purchaser do have common owners or are owned by subsidiaries or affiliates of the same company are exempt from the calibration requirements of section 95103(k) if one of the following is true: 1. The financial transaction meter is also used by other companies that do not share common ownership with the fuel supplier; or2. The financial transaction meter is sealed with a valid seal from the county sealer of weights and measures or from a county certified designee; or3. The financial transaction meter is operated by a third party.(B) Upstream ethanol and additive meters used to ensure proper blendstock percentage for finished gasoline are exempted from the calibration requirements of section 95103(k).(C) Non-financial transaction meters used by Public Utility Gas Corporations for purposes of reporting natural gas supplier emissions are exempt from the calibration requirements in sections 95103(k)(1)-(6) if the supplier can demonstrate that the meters are operated and maintained in conformance with a standard that meets the measurement accuracy requirements of the California Public Utilities Commission General Order 58A (1992).(8) For units and processes that operate continuously with infrequent outages, it may not be possible to meet deadlines for the initial or subsequent calibrations of a flow meter or other fuel measurement or sampling device, or inspection of orifice plates without disrupting normal process operation. In such cases, the owner or operator may submit a written request to the Executive Officer to postpone calibration or inspection until the next scheduled maintenance outage. Such postponements are subject to the procedures of section 95103(k)(9) and must be documented in the monitoring plan that is required under section 95105(c).(9) In cases of continuously operating units and processes where calibration or inspection is not possible without operational disruption, the operator must demonstrate by other means to the satisfaction of the Executive Officer that measurements used to calculate GHG emissions and product data still meet the accuracy requirements of section 95103(k)(6). The Executive Officer must approve any postponement of calibration or required recalibration beyond January 1, 2012.(A) A written request for postponement must be submitted to the Executive Officer not less than 30 days before the required calibration, recalibration or inspection date. The Executive Officer may request additional documentation to validate the operator's claim that the device meets the accuracy requirements of this section. The operator shall provide any additional documentation to ARB within ten (10) working days of a request by ARB.(B) The request must include: 1. The date of the required calibration, recalibration, or inspection;2. The date of the last calibration or inspection;3. The date of the most recent field accuracy assessment, if applicable;4. The results of the most recent field accuracy assessment, if applicable, clearly indicating a pass/fail status;5. The proposed date for the next field accuracy assessment, if applicable;6. The proposed date for calibration, recalibration, or inspection which must be during the time period of the next scheduled shutdown. If the next shutdown will not occur within three years, this must be noted and a new request must be received every three years until the shutdown occurs and the calibration, recalibration or inspection is completed.7. A description of the meter or other device, including at a minimum: e. annual emissions calculated or annual product data reported using data from the device,f. sources for which the device is used to calculate emissions or product data,g. calibration or inspection procedure,h. reason for delaying calibration or inspection,i. proposed method to assure the accuracy requirements of section 95103(k)(6) are met,j. name, title, phone number and e-mail of contact person capable of responding to questions regarding the device.(10) If the results of an initial calibration, recalibration, or field accuracy assessment fail to meet the required accuracy specification, and the emissions or product data estimated using the data provided by the device represent more than 5 percent of total facility emissions or product data on an annual basis, the operator must demonstrate by other means to the satisfaction of the verifier or ARB that measurements used to calculate GHG emissions and product data still meet the +5 percent accuracy requirements going back to the last instance of successful field accuracy assessment or calibration of the device. Where the results of an initial calibration, recalibration, or field accuracy assessment fail to meet the accuracy specifications, the verifier shall note at a minimum a nonconformance as part of the emissions data verification statement.(11) When using an inventory measurement, stock measurement, or tank drop measurement method to calculate volumes and masses, the method must be accurate to +5 percent for the time periods required by this article, including annually for covered product data. Techniques used to quantify amounts stored at the beginning and end of these time periods are not subject to the calibration requirements of this section. Uncertainties in beginning and end amounts are subject to verifier review for material misstatement under section 95131(b)(12) of this article. If any devices used to measure inputs and outputs do not meet the requirements of paragraphs (1)-(10) above, the verifier must account for this uncertainty when evaluating material misstatements. Reported values must be calculated using the following equations: Fuel consumed (volume or mass) = (inputs during time period - outputs during time period) + (amount stored at beginning of time period) - (amount stored at end of time period)
Product produced (volume or mass) = (outputs during time period - inputs during time period) + (amount stored at end of time period - amount stored at beginning of time period)
(l)Reporting and Verifying Product Data. The reporting entity must separately identify, quantify, and report all product data as specified in sections 95110-95124 and 95156 of this article. It is the responsibility of the reporting entity to obtain verification services for the product data. Product data will be evaluated for conformance and material misstatement independent of GHG emissions data. Covered product data is evaluated for material misstatement and conformance, while the remaining reported product data is evaluated for conformance only. Reporting entities must exclude inaccurate covered product data, and may elect to exclude accurate covered product data. Reporting entities that exclude covered product data must report a description of the excluded data and an estimated magnitude using best available methods. The excluded covered product data will not be used for the material misstatement assessment or for the total covered product data variable described in section 95131(b)(12)(A). Operators of cement plants may not exclude covered product data.(m)Changes in Methodology. Except as specified below, where this article permits a choice between different methods for the monitoring and calculation of GHGs and product data, the operator must use the method chosen for all future emissions data reports, except as provided pursuant to sections 95103(m)(1) and (2). (1) Changes in Prescribed Methods. (A) Permanent Improvement in Monitoring or Calculation Methodology for Emissions Data. The operator or supplier is permitted to permanently improve the emissions or product data monitoring or calculation method to a higher-tier monitoring or calculation method specified in this article, such as the addition of a continuous emissions monitoring system. Permanent improvements to emissions monitoring or calculation methods do not require approval in advance by the Executive Officer; however, the operator or supplier must notify ARB by the reporting deadline for the applicable reporting year.(B) Permanent Change to a Lower-Tier Methodology for Emissions Data. The operator or supplier is permitted to submit a request for approval of a permanent change to a lower-tier monitoring or calculation method specified in this article for emissions data. The request must be provided to ARB prior to January 1 of the year for which the data will be reported, and must be approved by the Executive Officer and implemented per the timing requirements in sections 95103(m)(2)-(3). The request must include a description of why the change in method is being proposed, a detailed description of the data that are affected by the method change, and a demonstration of differences in estimated data under the current and proposed methods.(C) Permanent changes to all covered product data monitoring or calculation methods must be submitted to ARB pursuant to section 95103(m)(2), except in the circumstances described in section 95103(m)(4).(2) Alternative Methods. If an operator or supplier identifies a situation where conventional metering or methods are not feasible, the operator may submit a request to the Executive Officer for approval of an alternative measurement/monitoring method that achieves accuracy at an equivalent level to the +5 percent required by section 95103(k)(6). The request must include a description of why the change in method is being proposed, include a detailed description of the data that are affected by the alternative measurement/monitoring method, and include a demonstration of differences in estimated data under the current and proposed methods. ARB will make an approval determination based on the necessity of the alternative method and whether the operator or supplier can sufficiently demonstrate accuracy of the method during verification. The alternative method request must be provided to ARB prior to January 1 of the year for which the new method would be implemented for data collection, and must be approved by the Executive Officer. If ARB approves the alternative method, and upon request by the reporting entity, ARB may also determine whether the methodology can be applied to the current data year based on the information submitted pursuant to this section. In order to apply the method to the current data year, the reporting entity must show that they have collected the necessary data to apply the method for the entire current reporting year.(3) When permitted under sections 95103(m)(1) and (2), a change in the calculation or monitoring method must be made for an entire data year and apply to the start of a data year, except in the circumstances described in section 95103(m)(4).(4) Use of a Temporary Methodology. The operator or supplier is permitted to temporarily modify the emissions or product data monitoring or calculation method when necessary for the avoidance of missing data or to comply with the missing data provisions of this article. For emissions data, in the event of an unforeseen breakdown in fuel analytical data monitoring equipment or CEMS equipment, operators and suppliers must use the procedures in section 95129(h) and section 95129(i), respectively, for seeking approval of interim data collection procedures. For all other instances that temporary methods are used, ARB must be notified by the reporting deadline of the following information: a description of the temporary method, the affected data, and the duration that the temporary method was used. A temporary method may be used for a period not to exceed 365 days unless the method is concurrently or subsequently submitted and approved by the Executive Officer as a permanent method per the requirements in section 95103(m)(1)(B) or (2). Operators and suppliers must be able to demonstrate during verification that the temporary method provides data accuracy within +5 percent as specified in section 95103(k)(6). Covered product data that does not meet the required accuracy specification must be excluded using the procedure in section 95103 (l) to avoid an adverse verification statement.(5) When regulatory changes impose new or revised reporting requirements or calculation methods on an operator or supplier, the monitoring and calculation method must be in place on January 1 of the year in which data is first required to be collected pursuant to the reporting requirements.(n)Changes in Ownership or Operational Control. If a reporting entity undergoes a change of ownership or operational control, the following requirements apply regarding notifications to ARB and reporting responsibilities. (1)ARB Notifications. Prior to the change of ownership or operational control, the previous owner or operator of the reporting entity and the new owner or operator of the reporting entity must provide the following information to ARB. Required information must be submitted to the ARB email account: ghgreport@arb.ca.gov (A) The previous owner or operator must notify ARB via email of the ownership or operational control change including the name of the new owner or operator and the date of the ownership or operational control change.(B) The new owner or operator must notify ARB via email of the ownership or operational control change, including the following information: 1. Previous owner or operator;2. New owner or operator;3. Date of ownership or operator change.4. Name of a new Designated Representative pursuant to section 95104(b) for the affected entity's account in the California Reporting Greenhouse Gas Reporting Tool (Cal e-GGRT) specified in section 95104(e);(2)Reporting Responsibilities. Except as specified in section 95103(n)(2)(D), the owner or operator of record at the time of a reporting or verification deadline specified in this article has the responsibility for complying with the requirements of this article, including certifying that the emissions data report is accurate and complete, obtaining verification services, and completing verification.(A) Except as specified in section 95103(n)(2)(D), the owner or operator of record at the time of a reporting deadline is responsible for submitting the emissions data report covering the complete calendar year data.(B) Except as specified in section 95103(n)(2)(D), if an ownership change takes place during the calendar year, reported data must not be split or subdivided for the year, based on ownership. A single annual data report must be submitted for the entity by the current owner or operator. This report must represent required data for the entire, calendar year.(C) Previous owners or operators are required to provide data and records to new owners or operators that is necessary and required for preparing annual emissions data reports required by this article.(D) Fuel suppliers that cease to have reportable emissions as a result of an ownership change that affects supplier operations retain the responsibility for complying with the requirements of this article, including certifying that the emissions data report is accurate and complete, obtaining verification services, and completing verification, for the emissions from all fuel transactions that occurred prior to the date of the change of ownership.(o)Addresses. The following address shall be substituted for the addresses provided in 40 CFR § 98.9, and used for any necessary notifications or materials that are not submitted by other means: MANAGER, CLIMATE CHANGE REPORTING SECTION
PROGRAM PLANNING AND MANAGEMENT BRANCH
INDUSTRIAL STRATEGIES DIVISION
CALIFORNIA AIR RESOURCES BOARD
P.O. BOX 2815
SACRAMENTO, CA 95812
Cal. Code Regs. Tit. 17, § 95103
1. New section filed 12-2-2008; operative 1-1-2009 (Register 2008, No. 49).
2. Amendment of section heading, section and NOTE filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
3. Amendment filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
4. Amendment filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
5. Amendment of subsection (h), repealer and new subsection (h)(1), repealer of subsections (h)(2)-(11), amendment of subsections (k)(2) and (l)-(m)(1), new subsection (m)(2), repealer and new subsection (m)(3), subsection renumbering, repealer of subsection (m)(4), amendment of newly designated subsection (m)(4) and amendment of subsection (n)(1)(B)4. filed 12-31-2014; operative 1-1-2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
6. Amendment filed 9-1-2017; operative 1-1-2018 (Register 2017, No. 35).
7. Amendment of subsection (h), repealer of subsections (h)(1)-(2) and (h)(5)-(6), new subsection (h)(1), subsection renumbering and amendment of subsection (o) filed 3-29-2019; operative 4-1-2019 pursuant to Government Code section 11343.4(b)(3) (Register 2019, No. 13). Note: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health and Safety Code.
1. New section filed 12-2-2008; operative 1-1-2009 (Register 2008, No. 49).
2. Amendment of section heading, section and Note filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
3. Amendment filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
4. Amendment filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
5. Amendment of subsection (h), repealer and new subsection (h)(1), repealer of subsections (h)(2)-(11), amendment of subsections (k)(2) and (l )-(m)(1), new subsection (m)(2), repealer and new subsection (m)(3), subsection renumbering, repealer of subsection (m)(4), amendment of newly designated subsection (m)(4) and amendment of subsection (n)(1)(B)4. filed 12-31-2014; operative 1/1/2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
6. Amendment filed 9-1-2017; operative 1/1/2018 (Register 2017, No. 35).
7. Amendment of subsection (h), repealer of subsections (h)(1)-(2) and (h)(5)-(6), new subsection (h)(1), subsection renumbering and amendment of subsection (o) filed 3-29-2019; operative 4/1/2019 pursuant to Government Code section 11343.4(b)(3) (Register 2019, No. 13).